Real time tracking of bending forces and fatigue in a tubing guide

ABSTRACT

A coiled tubing deployment system includes an offshore rig having a reel positioned thereon and coiled tubing wound on the reel. A tubing guide is operatively coupled to receive the coiled tubing and to direct the coiled tubing into the water, with a weight sensor positioned to measure the weight of the portion of coiled tubing deployed into the water. A first set of bend sensors are positioned at a first location on the tubing guide to measure a real-time strain assumed by the tubing guide at the first location. A data acquisition system is communicably coupled to the weight sensor and the first set of bend sensors, and receives and processes weight measurement signals and bend sensor signals in order to provide an output signal indicative of a real-time bending fatigue of the tubing guide.

TECHNICAL FIELD

The present technology pertains to riser-less applications of coiled tubing in well operations, and more specifically to systems and methods for measuring real-time induced fatigue.

BACKGROUND

Subterranean or subsea well operations are often complex and expensive undertakings, extending to depths of hundreds or thousands of meters below the surface. Access to the well is often provided by way of coiled tubing driven downhole by an injector located at the surface of the operation. Despite being constructed of relatively durable materials, the coiled tubing may plastically deform while it is deployed, particularly in the presence of ocean forces. As such, coiled tubing is often used in conjunction with risers, which provide rigidity or other structural support.

In a riser-less configuration, coiled tubing is often used in conjunction with a tubular support member, which assumes some portion of the bending forces and fatigue caused by subsea currents, ocean heaving, and other dynamic ocean phenomena. Such dynamic ocean phenomena are difficult, if not impossible, to predict or model. As a result, unknown fatigue may be introduced into the tubular support member, making it difficult or impossible to determine a fatigue life or remaining usable lifespan of the tubular support member.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other advantages and features of the disclosure can be obtained, a more particular description of the principles briefly described above will be rendered by reference to the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1A illustrates a schematic diagram of an example coiled tubing deployment system that may embody the principles of the present disclosure.

FIG. 1B illustrates an enlarged view of a portion of the coiled tubing deployment system of FIG. 1.

FIG. 2 illustrates a block diagram of an example data acquisition system.

DETAILED DESCRIPTION

Various elements of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure.

Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims, or can be learned by the practice of the principles set forth herein.

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features. The description is not to be considered as limiting the scope of the embodiments described herein.

The term “coupled” is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to or indicative of physical connections.

The approaches set forth herein describe real-time tracking and recording of the bending forces that occur on a tubing guide when it is used in riser-less applications. Each time the coiled tubing is deployed through a tubing guide, the coupled tubing guide and coiled tubing apparatus incurs bending forces due to the movement of one or more portions of the coiled tubing relative to the tubing guide. More particularly, the tubing guide serves to relieve the coiled tubing from some portion of these bending forces, which may extend the usable lifespan of the coiled tubing. Bearing these bending forces causes the tubing guide to fatigue over time, with its usable lifespan being dependent upon the cumulative time history of bending forces that it has experienced. A fatigue tracking system is used to obtain and store dynamic fatigue measurements of the tubing guide as the coiled tubing interacts with the oceanic environment. Strain or gyroscopic sensors may be coupled to the tubing guide to measure bending forces induced at a specific location on the tubing guide, and these measurements may be processed by a data acquisition system to yield a fatigue measurement. As a result, a fatigue history file may be generated that maps the fatigue assumed by the tubing guide at any given point along its length, which may prove advantageous in enabling tubing guide lifespans to be lengthened and optimized.

Disclosed is a system and method for real-time tracking and recording of the bending forces that occur on a tubing guide when it is used in riser-less applications. The method comprises measuring a weight of coiled tubing deployed off an offshore rig, measuring a real-time strain assumed by the tubing guide at a first location on the tubing guide with a first set of bend sensors, and receiving and processing the one or more weight measurement signals and the one or more first bend sensor signals with a data acquisition system communicably coupled to the weight sensor and the first set of bend sensors; wherein the sensor measurements are used to generate an output signal with the data acquisition system indicative of real-time bending fatigue of the tubing guide at select locations along the tubing guide.

The disclosed system and method are best understood in the context of the larger systems in which they operate. Accordingly, FIG. 1A shows an illustrative riser-less offshore coiled tubing deployment system 100. As illustrated, the coiled tubing deployment system 100 (hereafter “the system 100”) may include or otherwise be used in conjunction with an offshore rig 102 configured to operate in an offshore environment that includes a body of water 104. As illustrated, the offshore rig 102 may comprise a floating service vessel or boat. The offshore rig 102 may comprise any offshore platform, structure, or vessel used in subsea operations common to the oil and gas industry. The water 104 may comprise any body of water including, but not limited to, an ocean, a lake, a river, a stream, or any combination thereof.

The offshore rig 102 may be used to deploy coiled tubing 106 into the water 104 for an assortment of subsea operations or purposes. For example, coiled tubing 106 may be deployed for a well intervention operation where the coiled tubing 106 is coupled to or otherwise inserted into a subsea wellhead (not shown). Coiled tubing 106 may be deployed as a conduit or umbilical used to convey fluids or power to a subsea location (not shown), such as a wellhead, a submerged platform, or a subsea pipeline. The coiled tubing 106 may be made of a variety of deformable materials, including, but not limited to, a steel alloy, titanium, other suitable metal-based materials, thermoplastic, composite materials, and any combination thereof. The coiled tubing 106 may have a diameter of about 3.5 inches, but may alternatively have a diameter that is greater or less than 3.5 inches, without departing from the scope of the disclosure.

The coiled tubing 106 may be deployed from a reel 108 positioned on the offshore rig 102, here illustratively mounted on the surface of deck 109. The coiled tubing 106 may be wound multiple times around the reel 108 for ease of transport, and a fluid source 110 may be communicably coupled to the coiled tubing 106 via a fluid conduit 112 and configured to convey a pressurized fluid into the coiled tubing 106.

From the reel 108, coiled tubing 106 may be fed into a guide arch 114, commonly referred to in the oil and gas industry as a “gooseneck”. The guide arch 114 redirects the coiled tubing 106 toward a tubing guide 116, operatively coupled to the guide arch 114 and fixed to the frame of the offshore rig 102. The tubing guide 116 may be directly coupled to the guide arch 114. As illustrated, the tubing guide 116 may be indirectly coupled to the guide arch 114 with one or more structural components interposing the tubing guide 116 and the guide arch 114. The guide arch 114 may comprise a rigid structure with a known radius. As the coiled tubing 106 is conveyed through the guide arch 114, the coiled tubing 106 may be plastically deformed and otherwise re-shaped and re-directed for receipt by the tubing guide 116 located below.

The tubing guide 116 may be any device or structure used to convey the coiled tubing 106 into the water 104. For example, the tubing guide 116 may comprise a bend stiffener or a bend restrictor. As illustrated, the tubing guide 116 may include a flange 118 and a tapering body 120, the two of which may be coupled to one another or integrally formed with one another. The flange 118 may rest on the deck 109 of the offshore rig 102, and the tapering body 120 may extend from the flange 118 through a hole 122 defined through the deck 109, such that the tubing guide 116 is able to convey the coiled tubing 106 into the water 104. As illustrated, the tapering body 120 may extend fully or partially into the water 104 such that the coiled tubing 106 is deployed directly into the water 104. The tapering body 120 may not extend into the water 104, such that the coiled tubing 106 is deployed through the ambient air before it enters the water 104.

The flange 118 may operate to support and couple the tubing guide 116 to the offshore rig 102, and may also provide an upper mounting location on which to attach components such as injector 124. Accordingly, the flange 118 may be characterized by any box-type frame or other structural geometry capable of accomplishing the aforementioned tasks. The flange 118 may also be an annular frame, provided with a circular opening about its vertical axis, the opening having a diameter greater than or equal to the outer diameter of the coiled tubing 106 such that coiled tubing 106 makes contact with the interior surface of the tubing guide 116 when deployed through flange 118, thereby transferring some portion of the bending forces to the tubing guide 116 by virtue of this physical contact. The circular opening extends through the full length of the tapering body 120 at substantially the same diameter, thereby defining an inner diameter of the tubing guide 116, such that coiled tubing 106 may be deployed through the full length of tubing guide 116, such as when it may be driven downwards by the injector 124.

The tubing guide 116 may be configured such that its height or vertical length is 6 meters, although it is appreciated that this dimension may be adjusted as needed relative to the outer diameter of the coiled tubing 106, the water depth, and expected severity of dynamic ocean forces, for example. The tubing guide 116 may be triangular or conical in shape, with a maximum horizontal width occurring at the flange 118, or where the tubing guide 116 is otherwise secured to the offshore rig 102, although it is appreciated that other geometries may be employed without affecting the scope of the disclosure.

The tubing guide 116 may be configured to protect the coiled tubing 106 at a critical location of high strain or bending forces. Tubing guide 116 may be made of a material similar to that of coiled tubing 106, and therefore, may increase material properties, such as rigidity, of the portion of the coiled tubing 106 being conveyed through the tubing guide 116 at any given moment. The size or thickness of tubing guide 116, wherein the thickness of tubing guide 116 at a given height is defined by the difference between the outer diameter and inner diameter of the tubing guide 116, may serve to spread critical loads assumed by the coiled tubing 106 over the length of the tubing guide 116, which may help improve the working lifespan of the coiled tubing 106. The tubing guide 116 may include a liner (not shown) that directly contacts the coiled tubing 106 as it passes through the interior of tubing guide 116. As will be appreciated, this may prevent or reduce the magnitude of the abrasive contact between the materials of the tubing guide 116 and the coiled tubing 106. The liner may be composed of brass or other metal alloys of a type distinct from those used in either tubing guide 116 or coiled tubing 106, or may be composed of one or more plastics or polymers.

An injector 124 may be secured to the offshore rig 102 and interposes the guide arch 114 and the tubing guide 116. A support frame 126 may be included to couple the injector 124 to the tubing guide 116. The injector 124 may be configured to advance or retract the coiled tubing 106 during the deployment process, and the injector 124 may include a plurality of internal gripping elements or wheels (not shown) configured to engage the outer surface of the coiled tubing 106 to either pull the coiled tubing 106 from the reel 108 and advance it into the tubing guide 116, or retract the coiled tubing 106 from the water 104 to be wound again on the reel 108. However, the injector 124 may be omitted and the weight of the coiled tubing 106 may instead be used as means to compel downward movement during deployment through the tubing guide 116, and the reel 108 may be motorized to retract the coiled tubing 106. The coiled tubing 106 may be secured to deck 109 or some other surface of the offshore rig 102 such that one or more of the reel 108, the guide arch 114, and the injector 124 may not be presented or otherwise coupled to the coiled tubing 106.

In riser-less subsea applications, as shown in FIG. 1, bending stresses and additional forces can be assumed by the coupled apparatus comprising coiled tubing guide 116 and coiled tubing 106, as the coiled tubing 106 is deployed through tubing guide 116 and into the water 104. More particularly, in cases where the water 104 is open ocean, subsea currents, ocean heaving, waves, and other dynamic oceanic phenomena can all place strain and bending forces on the coiled tubing as it is deployed. Over time, these bend cycles induce considerable fatigue on the coiled tubing 106 through repeated stress and strain, ultimately affecting the overall usable lifespan of the coiled tubing 106. By coupling the coiled tubing 106 to a tubing guide 116, such as a bend stiffener, a portion of the strain and bending forces are transferred to the tubing guide 116, thereby extending the overall usable lifespan of the coiled tubing 106.

This extension of the usable lifespan of the coiled tubing 106 comes at the expense of a reduction in the usable lifespan of the tubing guide 116, where the usable lifespan of the tubing guide 116 is inversely correlated with the number of bending cycles it has endured. This cyclic loading of bending forces may cause the tubing guide 116 to deform, plastically or elastically, with both types of deformation inducing material fatigue in the tubing guide 116. A fatigue life of the tubing guide 116 is defined as a number of cycles of a specified character that the tubing guide 116 sustains before a failure of a specified nature occurs. For example, the failure may be defined to be the appearance of a visible crack or the fracture of the material, although it is appreciated that various other failure criteria may be employed to define the fatigue life of the tubing guide 116.

While fatigue and bending force calculations are generally understood as they pertain to static objects and environments, ascertaining the fatigue and bending forces assumed by the tubing guide 116 is an uncertain process, in view of the interaction with the unpredictable dynamic environment of the water 104, which provides essentially no known variables. According to the present disclosure, the bending forces assumed by the tubing guide 116 may be monitored and quantified in real-time and those measurements may be mapped along the length of the tubing guide 116 to determine a fatigue life of the tubing guide 116.

To monitor the bending and fatigue of the tubing guide 116 in real-time, the system 100 may further include a fatigue tracking system 128. The fatigue tracking system 128 may provide a reliable method for establishing and recording, both in real-time and in memory mode, the bending forces that are assumed by the tubing guide 116. As described below, the fatigue tracking system 128 may be configured to record the resultant forces and bending levels encountered by the tubing guide 116 and link those measurements back to the location on the tubing guide 116 where the forces were assumed. As a result, induced fatigue for the tubing guide 116 may be determined from the bending forces and mapped to a fatigue history file. Once the tubing guide 116 begins to reach predetermined fatigue limits, or its fatigue life, an operator may consider retiring the tubing guide 116, based on the fatigue history file, in order to avoid failure.

As illustrated, the fatigue tracking system 128 may include a plurality of sensors and devices, each communicably coupled to a data acquisition system 130 configured to receive and process signals deriving from each sensor or device. The data acquisition system 130 may be a computer system, for example, that includes a memory, a processor, and computer readable instructions that, when executed by the processor, cause the computer system to process the sensor signals to provide an output signal 132, which may be conveyed to a peripheral device 142 for display. Data corresponding to the construction parameters of the coiled tubing 106 and the tubing guide 116 may be provided to the data acquisition system 130 for reference. Construction parameters of the coiled tubing 106 may include the sections, lengths, material grade, length, outer diameter, and inner diameter of the coiled tubing 106. Construction parameters of the tubing guide 116 may include the material grade, length, outer diameter, and inner diameter of the tubing guide 116, wherein one or more of the aforementioned construction parameters may vary with the length of the tubing guide 116.

The fatigue tracking system 128 may further include a pressure transducer or sensor 134 used to measure the real-time pressure within the coiled tubing 106 during operation. The pressure sensor 134 may be fluidly coupled to the coiled tubing 106, and more particularly, communicably coupled to the coiled tubing 106 at 1 fluid conduit 112, which provides pressurized fluid into the coiled tubing 106 from the fluid source 110. The real-time pressure detected by the pressure sensor 134 may be conveyed to the data acquisition system 130 for processing, and more particularly, the data acquisition system 130 may take into consideration the detected pressure in calculating fatigue on the tubing guide 116. The data acquisition system 130 may also use the detected pressure in calculating resultant forces, internal or external, on the tubing guide 116 that arise due to the detected pressure within the coiled tubing 106.

The fatigue tracking system 128 may further include a transducer or weight sensor 137 that is used to measure the real-time surface weight of the coiled tubing 106 deployed during the operation. The weight sensor 137 may be coupled indirectly to the coiled tubing 106 and, more particularly, via the design of the frame of the injector 124. If the injector 124 is omitted, the weight sensor 137 may be coupled via a mechanism (not shown) that transfers the weight of the coiled tubing 106 onto the deck 109. Such a mechanism may comprise, for example, a work window into which a set of slip rams can be used to hold the coiled tubing 106 stationary, or may comprise, as further example, a load cell located below the guide arch 114. The real-time weight measurements detected by the weight sensor 137 may be conveyed to the data acquisition system 130 for processing, and the data acquisition system 130 may take into consideration the detected weight in calculating fatigue on the tubing guide 116.

The fatigue tracking system 128 may further include a first set of bend sensors 138 a located at a first location on the tubing guide 116. More particularly, the first set of bend sensors 138 a may be coupled to the tapered body 120 below the flange 118 and may be configured to measure real-time strain, particularly as this strain develops in response to the coiled tubing 106 being deployed into the water 104. The first location on the tubing guide 116 may indicate a certain height or vertical length along the tubing guide 116, about which the bend sensors may be circumferentially arranged in symmetric fashion. The first set of bend sensors 138 a may include at least one of a strain sensor or a gyroscopic sensor in order to determine the strain on the tubing guide 116 at the first location. The highest strain readings and critical bending points for the tubing guide 116 will be just below the flange 118. Sensor signals derived from the first set of bend sensors 138 a may be conveyed to the data acquisition system 130 for processing.

The fatigue tracking system 128 may include at least one more set of bend sensors, shown in FIG. 1A as a second set of bend sensors 138 b located at a second location along the tubing guide 116, and a third set of bend sensors 138 c located at a third location on the tubing guide 116. The second and third locations may be below the first location and otherwise at locations along the tapered body 120 that exhibit smaller thicknesses as compared to the thickness at the first location. Similar to the first set of bend sensors 138 a, the second and/or third set of bend sensors 138 b and/or 138 c may include at least one of a strain sensor or a gyroscopic sensor in order to determine the strain on the tubing guide 116 at the second and/or third location, respectively. Sensor signals derived from the second and third sets of bend sensors 138 b and 138 c may be conveyed to the data acquisition system 130 for processing, either alone or in conjunction with the sensor signals derived from the first set of bend sensors 138 a. As will be appreciated, the length of a given tubing guide 116 may vary from project to project, and as a result, the number of sets of bend sensors utilized may also vary, with a longer tubing guide generally requiring a greater number of bend sensors than a shorter tubing guide, all factors of different geometry notwithstanding. Moreover, since the obtained data will be recorded and matched to known locations along the tubing guide 116, an increased number of locations along the tubing guide 116 from which to collect sensor data may help enhance the accuracy of the measurements and subsequent fatigue calculations.

The fatigue tracking system 128 may further include a set of reference sensors 140 located at a fixed surface point, such as just above the tubing guide 116 and otherwise above the anticipated critical bending point. The reference sensors 140 may include one or more of an accelerometer, a strain sensor, and a gyroscopic sensor, and reference signals derived from the reference sensors 140 may be conveyed to the data acquisition system 130 for processing. The reference sensors 140 may be configured to monitor and detect heave and movement of the offshore rig 102 during operation. As illustrated, the reference sensors 140 are depicted as being coupled to the support frame 126, but may also be coupled at any fixed point above the tubing guide 116, without departing from the scope of the disclosure. One or more of a strain sensor and a gyroscopic sensor may be located prior to the tubing guide 116 and after the guide arch 114, while the accelerometer may be fixedly attached anywhere on the offshore rig 102 to detect the heave and movement of the offshore rig 102 during operation.

Referring briefly to FIG. 1B, with continued reference to FIG. 1A, an enlarged view of the exemplary support frame 126 is depicted as interposing the injector 124 and the tubing guide 116. As illustrated, the support frame 126 may operate as a work window to thereby facilitate access to the coiled tubing 106. Moreover, as illustrated, the set of reference sensors 140 is depicted as being positioned on a spool riser 141 located above the top of the tubing guide 116. The fatigue tracking system 128 may include multiple sets of reference sensors 140, in one or more locations above the tubing guide 116, without departing from the scope of the disclosure.

The measurements obtained by the reference sensors 140 may provide a control point or an offset that may be applied to at the measurements from at least the first set of bend sensors 138 a, and may also be applied to the measurements derived from the second and the third set of bend sensors 138 b and 138 c respectively. More particularly, the data acquisition system 130 may apply the measurements derived from the reference sensors 140 to remove the effect of the motion of the offshore rig 102 to which the tubing guide 116 may be fixed, thereby isolating the relative motion between the tubing guide 116 and the offshore rig 102, as it is this relative motion that gives rise to the strain and bending forces experienced by the tubing guide 116. Accordingly, the data acquisition system 130 may process the sensor signals derived from at least the first set of bend sensors 138 a in view of reference measurements derived from the reference sensors 140.

The fatigue tracking system 128 may include one or more accelerometers located at any fixed surface point on the offshore rig 102, and one or more accelerometer signals derived from the one or more accelerometers may be conveyed to data acquisition system 130 for processing. The one or more accelerometers may be configured to monitor and detect heave and movement of the offshore rig 102 during operation. The measurements provided by the one or more accelerometer signals may be used by the data acquisition system 130 to estimate the bending forces and fatigue in the tubing guide 116. From the one or more accelerometer signals, the relative position, and change in relative position, between the body of water 104 and the coupled system of the offshore rig 102, the tubing guide 116, and the coiled tubing 106, may be determined. The one or more accelerometers may be configured to provide real-time data to the data acquisition system 130, thereby allowing the data acquisition system 130 to determine the change in relative position mentioned above. Construction parameters for the coiled tubing 106, the tubing guide 116, and the offshore rig 102 may be stored in a memory of the data acquisition system 130, and may be used with the one or more accelerometer signals to estimate the real-time bending forces acting on the tubing guide 116, and thereby estimate the fatigue on the tubing guide 116. In this manner, the real-time bending forces and fatigue on tubing guide 116 may be estimated without the use of one or more of sensors 134, 137, and 138 a-c.

Each of the sensors 134, 137, 138 a-c, and 140 may be communicably coupled to the data acquisition system 130 and configured to transmit corresponding measurements thereto in real-time via any known means of telecommunication or data transmission. For instance, the data acquisition system 130 may be physically wired to one or more of the sensors 134, 137, 138 a-c, and 140, such as through electrical or fiber optic lines. One or more of the sensors 134, 137, 138 a-c, and 140 may be configured to wirelessly communicate with the data acquisition system 130, such as via electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry, radio frequency transmission, or any other combination thereof.

As illustrated, the data acquisition system 130 may be arranged at or near the offshore rig 102. The data acquisition system 130 may be remotely located relative to the offshore rig 102 and the tubing guide 116, wherein the sensors 134, 137, 138 a-c, and 140 are configured to communicate remotely with the data acquisition system 130, either wired or wirelessly.

The data acquisition system 130 may be configured to receive and process the various signals and measurements from the sensors 134, 137, 138 a-c, and 140 in conjunction with the construction parameters of the coiled tubing 106 and the tubing guide 116. The relative distances between one or more of the sensors 134, 137, 138 a-c, and 140 may also be used as configurable parameters within the data acquisition system 130 in generating the output signal 132, the output signal 132 comprising data indicative of a real-time bending fatigue of the tubing guide 116 at select locations along the tubing guide 116.

The output signal may further comprise real-time bending data corresponding to specific locations along the length of the tubing guide 116, the real-time bending data being used to determine the real-time bending fatigue of the tubing guide 116. One or more of the real-time bending data and the real-time bending fatigue may be stored in a memory of the data acquisition system 130 in a fatigue history file for the tubing guide 116. The output signal 132 may be transmitted to a peripheral device 142 for consideration and review by an operator. The peripheral device 142 may include, but is not limited to, a monitor (such as a display, a graphical user interface, a handheld device, a tablet, a mobile phone, etc), a printer, an alarm, or additional storage memory. The output signal 132 may be both stored in a memory of the data acquisition system 130 as a fatigue history file and transmitted to a peripheral device 142 for review. The peripheral device 142 may be configured to provide the operator with a graphical output or display that charts or maps the real-time fatigue at any given location on the tubing guide 116, wherein the real-time fatigue may be extrapolated from one or more of the measurements and signals generated by one or more of the sensors 134, 137, 138 a-c, and 140 and the construction parameters of the coiled tubing 106 and the tubing guide 116.

Given that the fatigue life of the tubing guide 116 is a function of the number and type of bending cycles sustained by the tubing guide 116, the data acquired by the data acquisition system 130 may be stored in memory such that it is historically tied to the specific tubing guide 116, thereby forming part of the fatigue history file corresponding to the tubing guide 116. It is appreciated that a number of different identification means may be used to tie a given tubing guide to its associated fatigue history file, including but not limited to, a bar code, a serial number, an identification number, a radio frequency identification tag, or any other unique identifier.

In some scenarios, a given tubing guide, such as the tubing guide 116, may be used in multiple deployments or subsea operations, wherein the tubing guide 116 may be exposed to dynamic ocean forces that vary in magnitude and type. Because the fatigue of the tubing guide 116 at a given moment in time is dependent on all of prior fatigue-inducing bending forces experienced by the tubing guide 116, the fatigue history file allows the data acquisition system 130 to make a more accurate determination of the real-time fatigue on the tubing guide 116.

Associated with the real-time fatigue on the tubing guide 116 is the remaining usable lifespan of the tubing guide 116, wherein the usable lifespan may be defined as the proximity of the real-time fatigue on the tubing guide 116 to the fatigue life of tubing guide 116, recalling that the fatigue life may be defined as the number of remaining bend cycles of a specified nature needed to cause some pre-defined failure of the tubing guide 116. The remaining usable lifespan may be represented in terms of time, such as the number of days until the anticipated failure of the tubing guide 116, given that the magnitude and nature of the current bend cycles remain the same. It is appreciated that various other representations of the remaining usable lifespan may be used, including but not limited to different units of time or probabilities of a failure occurring at a given location. Tit is further appreciated that the defined fatigue life of the tubing guide 116 may vary based on the type of deployment or subsea operation in which the tubing guide 116 is being used—that is, some deployments may require a relatively higher or lower threshold for determining that the useful life of the tubing guide 116 is over.

Operators may find it necessary to a select one or more tubing guides from a plurality of tubing guides, with the tubing guides to be used in some particular subsea operation. While, as previously mentioned, it is not possible to exactly predict and model the dynamic subsea forces that may be present for the particular subsea operation, some estimation may be made, for example based on a historical database of prior deployments in the same geographic area. As such, the efficiency of the usage of the tubing guides across multiple subsea operations may be improved, as any tubing guides with a remaining usable lifespan that is too short for the particular subsea operation will not be selected for use, thereby eliminating the expense of having to replace a broken or otherwise failed tubing guide while the subsea operation is still ongoing.

Referring now to FIG. 2, with continued reference to FIG. 1A, illustrated is a block diagram of the data acquisition system 130. As illustrated, the data acquisition system 130 may include a bus 202, a communications unit 204, one or more processors 206, a non-transitory computer readable medium (i.e., a memory) 208, a computer program 210, and a library or database 212. The bus 202 may provide electrical conductivity and a communication pathway among the various components of the data acquisition system 130. The communications unit 204 may employ wired or wireless communication technologies, or a combination thereof. The communications unit 204 can include communications operable among land locations, sea surface locations both fixed and mobile, and undersea locations both fixed and mobile. The computer program 210 may be stored partially or whole in the memory 208, and as generally known in the art, may be in the form of code, programs, routines, or graphical programming.

In exemplary operation, the data acquisition system 130 receives and samples one or more signals derived from the sensors 134, 137, 138 a-c, and 140. The processor 206 may be configured to transfer the sensor signals to the memory 208, which may encompass at least one of volatile or non-volatile memory. The computer program 210 may be configured to access the memory 208 and process the sensor signals in real-time. The sensor signals may be logged or otherwise stored in the memory 209 or the database 212 for post-processing review or analysis.

In processing the sensor signals, the computer program 210 may be configured to digitize the sensor signal and generate digital data. The computer program 210 may employ pre or post-acquisition processing by applying one or more signal amplifiers or signal filters in hardware or software. The computer program 210 may be configured to output the acquired signal in the time domain, thereby providing a time domain output. The computer program 210 may be capable of transforming and outputting the digital data in the frequency domain, thereby providing a frequency domain output. This transformation into the frequency domain may be accomplished using several different frequency based processing methods including, but not limited to, fast Fourier transforms (FFT), short-time Fourier transforms (STFT), wavelets, the Goertzel algorithm, or any other domain conversion methods or algorithms as would be appreciated by one of ordinary skill in the art. One or both of the time domain and frequency domain signals may be filtered using at least one of a low-pass filter, a medium-pass filter, a high pass filter, or other types of filters, without departing from the scope of the disclosure.

The computer program 210 may further be configured to query the database 212 for stored data corresponding to construction parameters of the coiled tubing 106 and the tubing guide 116, and relative distances between the sensors 134, 137, 138 a-c, and 140. Upon querying the database 212, the computer program 210 may be able to apply the construction parameters and relative distances to the measured signals. The computer program 210 may then deliver the output signal 132 comprising real-time bending data corresponding to specific locations along the length of the tubing guide 116. In some cases, as indicated previously, the output signal 132 may be provided to the peripheral device 142 for display. The data acquired by the data acquisition system 130 may be stored and historically tied to the fatigue history file corresponding to the tubing guide 116.

Methods according to the aforementioned description can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can comprise instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or special purpose processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be binaries, intermediate format instructions such as assembly language, firmware, or source code. Computer-readable media that may be used to store instructions, information used, and/or information created during methods according to the aforementioned description include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software.

The computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

Devices implementing methods according to these disclosures can comprise hardware, firmware and/or software, and can take any of a variety of form factors. Such form factors can include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device.

The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are means for providing the functions described in these disclosures.

Although a variety of information was used to explain aspects within the scope of the appended claims, no limitation of the claims should be implied based on particular features or arrangements, as one of ordinary skill would be able to derive a wide variety of implementations. Further and although some subject matter may have been described in language specific to structural features and/or method steps, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to these described features or acts. Such functionality can be distributed differently or performed in components other than those identified herein. Rather, the described features and steps are disclosed as possible components of systems and methods within the scope of the appended claims. Moreover, claim language reciting “at least one of” a set indicates that one member of the set or multiple members of the set satisfy the claim.

STATEMENTS OF THE DISCLOSURE INCLUDE

Statement 1: A coiled tubing deployment system, comprising: a coiled tubing positionable on an offshore rig, the offshore rig being deployable on water, the offshore rig being deployable on water, a tubing guide operatively coupled to receive the coiled tubing and to direct the coiled tubing into the water, a weight sensor positioned at a fixed point relative to the coiled tubing to measure a weight of the coiled tubing and to generate one or more weight measurement signals, a first set of bend sensors positioned at a first location on the tubing guide to measure a real-time strain assumed by the tubing guide at the first location and thereby generate one or more first bend sensor signals, and a data acquisition system communicably coupled to the weight sensor and the first set of bend sensors to receive and process the one or more weight measurement signals and the one or more first bend sensor signals, the data acquisition system providing an output signal indicative of a real-time bending fatigue of the tubing guide at select locations along the tubing guide.

Statement 2: The coiled tubing deployment system of Statement 1, wherein a reel is positioned on the offshore rig and the coiled tubing is wound on the reel.

Statement 3: The coiled tubing deployment system of Statement 1, wherein the one or more first bend sensor signals and the output signal indicative of real-time bending fatigue are stored in a memory of the data acquisition system as a fatigue history file for the tubing guide and used to calculate a fatigue of the tubing guide.

Statement 4: The coiled tubing deployment system of Statement 3, further comprising a second set of bend sensors positioned at a second location on the tubing guide to measure a real-time strain assumed by the tubing guide at the second location and thereby generate one or more second bend sensor signals to be received and processed by the data acquisition system and used in determining a real-time bending fatigue of the tubing guide at select locations along the tubing guide.

Statement 5: The coiled tubing deployment system of Statement 4, wherein the first set of bend sensors and the second set of bend sensors include at least one of a strain sensor or a gyroscopic sensor.

Statement 6: The coiled tubing deployment system of Statement 1, wherein the tubing guide includes a flange and a body that extends from the flange and wherein the first set of bend sensors is coupled to the body.

Statement 7: The coiled tubing deployment system of Statement 1, wherein construction parameters for the coiled tubing and the tubing guide are stored in the memory of the data acquisition system, and wherein the construction parameters are used to determine the real-time bending fatigue of the tubing guide.

Statement 8: The coiled tubing deployment system of Statement 1, further comprising a set of reference sensors coupled to the offshore rig at a fixed surface point to monitor and detect heave and movement of the offshore rig and generate reference signals, wherein the data acquisition system receives and processes the reference signals to remove motion effects of the offshore rig from the one or more first bend sensor signals in determining the real-time bending fatigue of the tubing guide.

Statement 9: The coiled tubing deployment system of Statement 8, wherein the set of reference sensors includes at least one of an accelerometer, a strain sensor, and a gyroscopic sensor.

Statement 10: The coiled tubing deployment system of Statement 9, further comprising an accelerometer being fixedly attached anywhere on the offshore rig to detect the heave and movement of the offshore rig and generate an accelerometer signal, wherein the data acquisition system, receives and processes the accelerometer signal to estimate the real-time bending fatigue of the tubing guide.

Statement 11: The coiled tubing deployment system of Statement 1, further comprising a peripheral device communicably coupled to the data acquisition system to receive the output signal and provide a graphical output corresponding to the real-time bending fatigue of the tubing guide at the select locations along the tubing guide.

Statement 12: A method, comprising: deploying coiled tubing from an offshore rig, receiving the coiled tubing with a tubing guide and directing the coiled tubing from the tubing guide into water below the offshore rig, measuring a weight of the coiled tubing with a weight sensor positioned at a fixed point relative to the coiled tubing and thereby generating one or more weight measurement signals, measuring a real-time strain assumed by the tubing guide at a first location on the tubing guide with a first set of bend sensors positioned at the first location and thereby generating one or more first bend sensor signals, receiving and processing the one or more weight measurement signals and the one or more first bend sensor signals with a data acquisition system communicably coupled to the weight sensor and the first set of bend sensors, and generating an output signal with the data acquisition system indicative of real-time bending fatigue of the tubing guide at select locations along the tubing guide.

Statement 13: The method of Statement 12, further comprising storing in a memory of the data acquisition system the one or more first bend sensor signals and the output signal indicative of real-time bending in order to obtain a fatigue history file for the tubing guide.

Statement 14: The method of Statement 13, further comprising: measuring a real-time strain assumed by the tubing guide at a second location on the tubing guide with a second set of bend sensors positioned at the second location and thereby generating one or more second bend sensor signals, and receiving and processing the one or more second bend sensor signals with the data acquisition system to determine the real-time bending fatigue of the tubing guide at select locations along the tubing guide.

Statement 15: The method of Statement 12, wherein the first set of bend sensors and the second set of bend sensors include at least one of a strain sensor or a gyroscopic sensor.

Statement 16: The method of Statement 12, wherein construction parameters for the coiled tubing and the tubing guide are stored in the memory of the data acquisition system, the method further comprising accessing the construction parameters in determining the real-time bending fatigue of the tubing guide.

Statement 17: The method of Statement 12, further comprising: monitoring and detecting real-time heave and movement of the offshore rig with a set of reference sensors coupled to the offshore rig at a fixed surface point, generating reference signals with the set of reference sensors indicative of the real-time heave and movement of the offshore rig, and receiving and processing the reference signals with the data acquisition system and thereby removing motion effects of the offshore rig from the one or more first bend sensor signals in determining the real-time bending fatigue of the tubing guide.

Statement 18: The method of Statement 12, further comprising: monitoring and detecting real-time heave and movement of the offshore rig with an accelerometer fixedly attached anywhere on the offshore rig; generating an accelerometer signal indicate of the real-time heave and movement of the offshore rig; and receiving and processing the accelerometer signal with the data acquisition system and thereby estimating the real-time bending fatigue of the tubing guide.

Statement 19: The method of Statement 13, further comprising: receiving the output signal with a peripheral device communicably coupled to the data acquisition system, and generating a graphical output corresponding to the real-time bending fatigue of the tubing guide at the select locations along the tubing guide.

Statement 20: The method of Statement 19, further comprising using the fatigue history file and generating a map of the fatigue on the tubing guide at the select locations along the tubing guide.

Statement 21: The method of Statement 19, further comprising using the fatigue history file and generating a graphical output corresponding to a fatigue of the tubing guide at the select locations along the tubing guide.

Statement 22: The method of Statement 19, wherein generating the graphical output comprises generating a map of the fatigue on the tubing guide at the select locations along the tubing guide.

Statement 23: The coiled tubing deployment system of Statement 1, wherein the offshore rig comprises a vessel selected from the group consisting of a service vessel, a boat, a floating platform, an offshore platform, a floating structure, and any combination thereof. 

1. A coiled tubing deployment system, comprising: a coiled tubing positionable on an offshore rig, the offshore rig being deployable on water; a tubing guide operatively coupled to receive the coiled tubing and to direct the coiled tubing into the water; a weight sensor positioned at a fixed point relative to the coiled tubing to measure a weight of the coiled tubing and to generate one or more weight measurement signals; a first set of bend sensors positioned at a first location on the tubing guide to measure a real-time strain assumed by the tubing guide at the first location and thereby generate one or more first bend sensor signals; and a data acquisition system communicably coupled to the weight sensor and the first set of bend sensors to receive and process the one or more weight measurement signals and the one or more first bend sensor signals, the data acquisition system providing an output signal indicative of a real-time bending fatigue of the tubing guide at select locations along the tubing guide.
 2. The coiled tubing deployment system of claim 1, wherein a reel is positioned on the offshore rig and the coiled tubing is wound on the reel.
 3. The coiled tubing deployment system of claim 1, wherein the one or more first bend sensor signals and the output signal indicative of real-time bending fatigue are stored in a memory of the data acquisition system as a fatigue history file for the tubing guide and used to calculate a fatigue of the tubing guide.
 4. The coiled tubing deployment system of claim 3, further comprising a second set of bend sensors positioned at a second location on the tubing guide to measure a real-time strain assumed by the tubing guide at the second location and thereby generate one or more second bend sensor signals to be received and processed by the data acquisition system and used in determining a real-time bending fatigue of the tubing guide at select locations along the tubing guide.
 5. The coiled tubing deployment system of claim 4, wherein the first set of bend sensors and the second set of bend sensors include at least one of a strain sensor or a gyroscopic sensor.
 6. The coiled tubing deployment system of claim 1, wherein the tubing guide includes a flange and a body that extends from the flange, and wherein the first set of bend sensors is coupled to the body.
 7. The coiled tubing deployment system of claim 1, wherein construction parameters for the coiled tubing and the tubing guide are stored in the memory of the data acquisition system, and wherein the construction parameters are used to determine the real-time bending fatigue of the tubing guide.
 8. The coiled tubing deployment system of claim 1, further comprising a set of reference sensors coupled to the offshore rig at a fixed surface point to monitor and detect heave and movement of the offshore rig and generate reference signals, wherein the data acquisition system receives and processes the reference signals to remove motion effects of the offshore rig from the one or more first bend sensor signals in determining the real-time bending fatigue of the tubing guide.
 9. The coiled tubing deployment system of claim 8, wherein the set of reference sensors includes at least one of an accelerometer, a strain sensor, and a gyroscopic sensor.
 10. The coiled tubing deployment system of claim 1, further comprising an accelerometer being fixedly attached anywhere on the offshore rig to detect the heave and movement of the offshore rig and generate an accelerometer signal, wherein the data acquisition system receives and processes the accelerometer signal to estimate the real-time bending fatigue of the tubing guide.
 11. The coiled tubing deployment system of claim 1, further comprising a peripheral device communicably coupled to the data acquisition system to receive the output signal and provide a graphical output corresponding to the real-time bending fatigue of the tubing guide at the select locations along the tubing guide.
 12. A method, comprising: deploying coiled tubing from an offshore rig; receiving the coiled tubing with a tubing guide and directing the coiled tubing from the tubing guide into water below the offshore rig; measuring a weight of the coiled tubing with a weight sensor positioned at a fixed point relative to the coiled tubing and thereby generating one or more weight measurement signals; measuring a real-time strain assumed by the tubing guide at a first location on the tubing guide with a first set of bend sensors positioned at the first location and thereby generating one or more first bend sensor signals; receiving and processing the one or more weight measurement signals and the one or more first bend sensor signals with a data acquisition system communicably coupled to the weight sensor and the first set of bend sensors; and generating an output signal with the data acquisition system indicative of real-time bending fatigue of the tubing guide at select locations along the tubing guide.
 13. The method of claim 12, further comprising storing in a memory of the data acquisition system the one or more first bend sensor signals and the output signal indicative of real-time bending in order to obtain a fatigue history file for the tubing guide.
 14. The method of claim 13, further comprising: measuring a real-time strain assumed by the tubing guide at a second location on the tubing guide with a second set of bend sensors positioned at the second location and thereby generating one or more second bend sensor signals; and receiving and processing the one or more second bend sensor signals with the data acquisition system to determine the real-time bending fatigue of the tubing guide at select locations along the tubing guide.
 15. The method of claim 14, wherein the first set of bend sensors and the second set of bend sensors include at least one of a strain sensor or a gyroscopic sensor.
 16. The method of claim 12, wherein construction parameters for the coiled tubing and the tubing guide are stored in the memory of the data acquisition system, the method further comprising accessing the construction parameters in determining the real-time bending fatigue of the tubing guide.
 17. The method of claim 12, further comprising: monitoring and detecting real-time heave and movement of the offshore rig with a set of reference sensors coupled to the offshore rig at a fixed surface point; generating reference signals with the set of reference sensors indicative of the real-time heave and movement of the offshore rig; and receiving and processing the reference signals with the data acquisition system and thereby removing motion effects of the offshore rig from the one or more first bend sensor signals in determining the real-time bending fatigue of the tubing guide.
 18. The method of claim 12, further comprising: monitoring and detecting real-time heave and movement of the offshore rig with an accelerometer fixedly attached anywhere on the offshore rig; generating an accelerometer signal indicative of the real-time heave and movement of the offshore rig; and receiving and processing the accelerometer signal with the data acquisition system and thereby estimating the real-time bending fatigue of the tubing guide.
 19. The method of claim 13, further comprising: receiving the output signal with a peripheral device communicably coupled to the data acquisition system; and generating a graphical output corresponding to the real-time bending fatigue of the tubing guide at the select locations along the tubing guide.
 20. The method of claim 19, further comprising using the fatigue history file and generating a map of the fatigue on the tubing guide at the select locations along the tubing guide. 